Often, an oil field service will be selected and tailored in response to information collected by logging while drilling and/or by exposing a region of a wellbore to a wireline tool. These methods require equipment that is delicate and expensive and methods that require human and computational resources that are burdensome, especially in remote locations or with wells that may generate smaller returns on investment. In formations that are in remote locations or that do not have recovery plans with the economic resources for these tools, low-cost, local, low technology methods are selected to roughly estimate the reservoir properties.
Some oil field services may require geomechanical properties of a formation for a variety of reasons without the use of a logging while drilling tool or wireline tool. There may be a need to complement tool failure. A wellbore may be drilled without core data or log information. A drilling regime may include multiple lateral wells from one initial wellbore and the costs for core and/or log data may be unreasonably burdensome. Some embodiments may use a drill string with no tools for logging. Some embodiments may be performed on site in near real time without time for data actualization, that is, the drill string may remain in the wellbore as people timely use the information available to them without remote mathematical analysis and without operating time lag. Some embodiments may manipulate the data in time to guide the completion time. Also, some of the techniques to address these issues, such as laboratory measurements and some logs, require post-analysis, and interpretation of the data that cannot be done within the drilling timeframe.
Further, while some vertical pilot wells are logged and evaluated in an unconventional play, stimulated horizontal wells are rarely logged or cored. The cost of acquiring the information and/or the associated rig time needed during acquisition (which means that the rig cannot be used for drilling or stimulation elsewhere) are two main reasons for this trend. On the other hand, most of the production from a horizontal well comes from a small portion of the completed section. A typical number is 70/30, implying that 70 percent of the production comes from 30 percent of the horizontal well. More efficient use of funds and resources is warranted. Change can only take place with better understanding of the reservoir and completion quality of the formations which require petrophysical and geomechanical data. The solution must be low cost and efficient in terms of delivery times (real or near real-time). It must not introduce any inefficiency into the development program (such as extended rig time for data acquisition) and must be based on a simple workflow that can be carried at the wellsite by non-experts.
Also, the hydraulic fracturing stimulation of unconventional organic shale reservoirs is performed today in mostly horizontal wells where heterogeneities of petrophysical and mechanical properties along the well are known to be very significant. Staging requires the identification of sections of the well with both good reservoir quality and good completion quality. Completion quality estimates rely on changes in elastic, rock strength, and stress properties along the well reflect variations (heterogeneity) of mechanical properties along the well.